Method for a fracturing fluid system at high temperatures

ABSTRACT

The method for well-stimulation through a wellbore in a rock formation is hydraulic fracturing under high temperature conditions. The method includes injecting a fracturing fluid system to the rock formation; fracturing the rock formation at a temperature between 150-260 degrees Celsius; and recovering fluid components of the fracturing fluid system from the wellbore and setting the proppant in the fractures. The fracturing fluid system includes proppant and a plurality of fluid components. The fluid components can include water, a gelling agent, and a stabilizer made of ascorbic acid. The ascorbic acid stabilizes viscosity of the gelling agent, adjusts pH, and delays cross linking. Amount of components and additional components, such as a cross-linking agent, a breaker, another adjusting agent and an inverting surfactant adjust the fracturing fluid system for well conditions and a type of treatment to be completed.

CROSS-REFERENCE TO RELATED APPLICATIONS

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STATEMENT REGARDING PRIOR DISCLOSURES BY THE INVENTOR OR A JOINTINVENTOR

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BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to fluid systems in the oil and gasindustry, in particular, a fracturing fluid system. In particular, thepresent invention relates to a fracturing fluid system with ascorbicacid for high temperatures. More particularly, the present inventionrelates to a fracturing fluid system with ascorbic acid for stableviscosity at temperatures between 150-260 degrees Celsius.

2. Description of Related Art Including Information Disclosed Under 37CFR 1.97 and 37 CFR 1.98.

Fluid systems transport materials and chemicals and perform work, suchas powering downhole tools with hydraulics, during drilling andproduction operations for oil and gas. Drilling mud is the lubricant andtransport material during drilling. The drilling mud fluid is pumpedfrom the surface to the wellbore with coolants and stabilizers toprovide relief to the mechanical tools in the extremely hot andpressurized environmental conditions at the drill bit. The pulverizedrock at the drill bit is suspended in the drilling mud and pumped backout of the borehole for removal. Fracturing fluid systems are the fluidspumped into the wellbore with a proppant in order to fracture a rockformation. A high pressure injection of fracturing fluid system at atarget depth creates cracks in rock formation, and the fracturing fluidsystem enters these cracks. The proppant, such as sand or otherparticulates, prevent the cracks from closing when the pressuredinjection of fluid stops. The fracture is held open by the proppant sothat the formation remains permeable by oil, gas, salt water, and otherfluids, which can now be pumped through the well.

Fracturing fluid systems are comprised of water, proppant, andadditives. The additives control rheological properties of thefracturing fluid system so as to allow the transport of proppant fordifferent formations under various conditions. High viscosity fracturingrelies on gelling agents, such as guar gum, to increase viscosity andsuspend the proppant for delivery as far as possible into the cracks ofthe fracture. High rate or high velocity relies on low friction and fastpumping fracturing fluid systems to reach deeper into a rock formation.Additives can be principally chosen for a desired ability to suspendproppant or to be pumped at a particular velocity.

Additives can also be selected for recovery of the fracturing fluidsystem. Once the proppant is delivered, the fluid components of thefracturing fluid system must be removed. Additional water can be pumpedto flush the fracture. During the fluid injection, additives can bereleased into the fracturing fluid system to alter the gelling agent, soas to reduce viscosity and more easily release the proppant fromsuspension. The fracturing fluid system waste contains the water andadditives, which can contaminate the environment. With so much waterbeing used, the amount of produced wastewater with additives is alsogreat. There is a risk to ground water, when fracturing fluid system isinjected and recovered, and there is a risk to surface water, whenproduced wastewater is stored in waste pits and retention ponds.Additives can be chosen to be more biologically friendly in order tolessen environmental impact.

Fracturing fluid systems fail, when the proppant is not delivered or notanchored in the fracture. The viscosity may be too high or the velocityis too slow, so that the proppant cannot reach deep enough into thecracks in the formation. The viscosity may be too low or the velocitytoo fast, so that the proppant is not suspending in the fluid componentlong enough to reach deep into cracks. Also, when the fluid componentwashes out of the fracture, the proppant must remain in the fracture,separate from the liquid components of the fracturing fluid system. Ifthe fracturing fluid system remains too viscous, the washing out maydislodge and carry proppant back out of the fracture.

With advances in the drilling to greater depths, the high temperatureconditions at the greater depths cause conventional fracturing fluidsystems to fail. Fracturing fluid systems with gelling agents losestability and cannot hold viscosity to suspend the proppant into theformation. The prior art discloses fracturing fluid systems withselected additives to account for these high temperature conditions.

U.S. Pat. No. 8,022,015, issued to Paul S. Carman et al. on 20 Sep.2011, discloses a method of fracturing with a phenothiazine stabilizer.Well treatment fluids and methods of treating high temperaturesubterranean formations of up to about 260 degrees C. are disclosed. Theadditives of the fracturing fluid include a gelling agent, a highmolecular weight synthetic copolymer, a phenothiazine stabilizer, and apH adjusting agent that maintains a pH in a range of about 4.5 to about5.25 for the fluids. The phenothiazine stabilizer is an electrondonating compound, which maintains viscosity of the gel by slowinghydrolysis of the fracturing fluid system at temperatures above 148.9degrees C. The method also requires a suitable crosslinking agent forthe getting agent and a high molecular weight synthetic polymer tomaintain viscosity at the high temperatures.

U.S. Pat. No. 8,691,734, issued to Paul S. Carman et al. on 8 Apr. 2014,also discloses a method of fracturing with a phenothiazine stabilizer.Foaming affects the amount of water and viscosity of the fracturingfluid system. This method includes a foaming agent, instead of a gellingagent, as an additive to reduce the amount of water required for thefracturing fluid system.

Phenothiazine is a known insecticide and treatment for worms inlivestock and humans. Derivatives of phenothiazine have been used inantipsychotic drugs. Phenothiazine is not biologically friendly, andthere is an elevated risk to the environment with potential insecticidescontaminating ground water. Furthermore, phenothiazine is not soluble inwater, but the fracturing fluid system is more than 90% water. Moresolvents are required to dissolve phenothiazine in the fracturing fluidsystem. The use of a foaming agent, instead of a gelling agent, furtherreduces the amount of water, but more solvents are still needed toaccommodate these high temperature fracturing fluid systems.

Advancement in drilling technology has not always permitted oil and gasproduction at certain depths with extreme environmental conditions oftemperature and pressure. The prior art discloses other additives forfracturing fluid systems, although these prior art references do notaddress high temperature conditions. Other additives to regulatestability of the fracturing fluid system under more conventionalconditions include various cross linking agents and stabilizers.Ascorbic acid is one such known additive.

The inherent properties of ascorbic acid, as an acid and as astabilizer, are known in the prior art. Ascorbic acid is a knownadditive in drilling fluids because of these inherent properties. Forexample, United States Publication No. 20150175877, published forShindgikar et al. on 25 Jun. 2015, discloses ascorbic acid as achelating agent to bind metal ions in a fracturing fluid system. U.S.Pat. No. 4,752,404, issued to Burns et al. on 21 Jun. 1988, teachesblends of water soluble polymers with ascorbic acid as a stabilizer orsequestering agent. U.S. Pat. No. 7,833,949, issued to Li et al. on 16Nov. 2010, describes another fracturing fluid system with apolysaccharide having ascorbic acid mentioned as a possible reducingagent. U.S. Pat. No. 7,678,745, issued to Parris et al. on 16 Mar. 2010,discloses a fracturing fluid system with an organic peroxide, includinga side note mentioning ascorbic acid as a stabilizer.

It is an object of the present invention to provide a method for wellstimulation by hydraulic fracturing a rock formation through a wellboreunder high temperature conditions.

It is another object of the present invention to provide a method forhydraulic fracturing a rock formation at a temperature range of 150-260degrees Celsius.

It is an object of the present invention to provide a method for wellstimulation by hydraulic fracturing, wherein the fracturing fluid systemhas ascorbic acid as a stabilizer.

It is another object of the present invention to provide a method forwell stimulation by hydraulic fracturing with a gel based fracturingfluid system having viscosity stabilized by ascorbic acid.

It is an object of the present invention to provide a method for wellstimulation by hydraulic fracturing with a fracturing fluid systemhaving a high molecular weight synthetic polymer as the gelling agent.

It is an object of the present invention to provide a method for wellstimulation by hydraulic fracturing, wherein the fracturing fluid systemhas ascorbic acid as a stabilizer and a pH adjusting agent.

It is another object of the present invention to provide a method forwell stimulation by hydraulic fracturing, wherein the fracturing fluidsystem with delayed cross-linking has ascorbic acid as a stabilizer, anda pH adjusting agent.

It is still another object of the present invention to provide a methodfor well stimulation by hydraulic fracturing, wherein the fracturingfluid system has ascorbic acid as a stabilizer and a pH adjusting agent,and another pH adjusting agent adjusted according to the amount ofascorbic acid and other additives.

It is an object of the present invention to provide a method for wellstimulation by hydraulic fracturing under high temperature conditions byinjecting a stable fracturing fluid system having a biologicallyfriendly stabilizer.

It is another object of the present invention to provide a method forwell stimulation by hydraulic fracturing under high temperatureconditions by injecting a stable well treatment fluid having astabilizer with less risk of environmental contamination.

These and other objectives and advantages of the present invention willbecome apparent from a reading of the attached specification.

BRIEF SUMMARY OF THE INVENTION

Embodiments of the present invention include a method forwell-stimulation through a wellbore in a rock formation, such ashydraulic fracturing. The method can include the steps of: injecting afracturing fluid system to the rock formation; fracturing the rockformation at a temperature between 150-260 degrees Celsius; andrecovering fluid components of the fracturing fluid system from thewellbore. The fracturing fluid system comprises a proppant, and aplurality of fluid components. The fluid components can be comprised ofwater, a gelling agent, and a stabilizer comprised of ascorbic acid. Theproppant is a granular material, which prevents fractures from closing,after the step of injecting. The gelling agent can be a high molecularweight synthetic polymer resistant to hydrolysis. For some embodiments,the fracturing fluid system further comprises a cross linking agent toincrease viscosity of the fracturing fluid system, an invertingsurfactant to hydrate the emulsion polymer in water, and breaker tofacilitate the step of recovering fluid components of the fracturingfluid system. The cross linking agent can increases viscosity of thefracturing fluid system by cross linking the gelling agent with metalions. Other fluid components can include sodium thiosulfate.

In the embodiments of the present invention, the ascorbic acid adjustspH of the fracturing fluid system, the other fluid components, evenbefore addition of a cross linking agent, having a pH ranging from about3.5 to 6.9. Additionally, there can be another pH adjusting agent addedto the fracturing fluid system after the stabilizer. Other additives canaffect the pH, so pH may need to be adjusted after the stabilizer. Theamount of the other pH adjusting agent is adjusted to maintain pHranging from about 3.5 to 6.9, after the amount of ascorbic acid is set.The ascorbic acid can delay cross linking of the gelling agent andprevent strong cross linking, such that there is no spike in apparentviscosity at the beginning of addition to the fracturing fluid system.Within the temperature range of 150-260 degrees Celsius, the ascorbicacid stabilizes apparent viscosity so that the fracturing fluid systemcan deliver the proppant to the fractures.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 is a graph illustration of rheological profiles of fracturingfluid systems at 180 degrees Celsius, showing embodiments of fracturingfluid systems of the method of the present invention.

FIG. 2 is a graph illustration of the rheological profiles of thefracturing fluid systems of FIG. 1, showing the first 15 minutes of FIG.1, wherein the start of cross linking is delayed, and wherein delay timedecreases with increasing loading of ascorbic acid.

FIG. 3 is a graph illustration of rheological profiles of fracturingfluid systems at 200 degrees Celsius, showing embodiments of fracturingfluid systems of the method of the present invention.

FIG. 4 is a graph illustration of the rheological profiles of thefracturing fluid systems of FIG. 3, showing the first 15 minutes of FIG.3, wherein the start of cross linking is delayed, and wherein delay timedecreases with increasing loading of ascorbic acid.

FIG. 5 is a graph illustration of rheological profiles of fracturingfluid systems at 230 degrees Celsius, showing embodiments of fracturingfluid systems of the method of the present invention.

FIG. 6 is a graph illustration of rheological profiles of fracturingfluid systems at 200 degrees Celsius, after shear history simulation at1350 s⁻¹ for five minutes, showing an embodiment of a fracturing fluidsystem of the method of the present invention.

FIG. 7 is a graph illustration of rheological profiles of fracturingfluid systems at 180 degrees Celsius, showing embodiments of fracturingfluid systems of the method of the present invention, when thefracturing fluid systems include a breaker as a fluid component.

DETAILED DESCRIPTION OF THE INVENTION

A method for well-stimulation through a wellbore in a rock formationincludes hydraulic fracturing. Conventional methods use fracturing fluidsystems to create fractures and to deliver proppant to the fractures.There can be additives to water based fracturing fluid systems forsuspending proppant or pumping at a particular velocity. At hightemperatures, the conventional fracturing fluid systems break down. Forexample, known gelling agents are polysaccharides, such as guar gum,which increase viscosity to suspend proppant. However, theseconventional fracturing fluid systems degrade under high temperatureconditions. Guar gum degrades too much under the conditions in deeperwells. The conventional fracturing fluid systems cannot functioneffectively at the depths of current deep wells. In the presentinvention, the method injects a fracturing fluid system, which is stableunder high temperature conditions.

Embodiments of the method of the present invention includes injecting afracturing fluid system into the rock formation, fracturing the rockformation at a temperature between 150-260 degrees Celsius, andrecovering the fluid components of the fracturing fluid system from thewellbore. The proppant is carried to the fractures, and most proppantremains lodged in the fracture. The fracturing fluid system comprisesthe proppant, and a plurality of fluid components. The fluid componentscan include water, a gelling agent, and a stabilizer of ascorbic acid.The proppant can be comprised of a granular material to preventfractures from closing, such as silica, bauxite, and ceramics.

Under high temperature conditions, the gelling agent is comprised of ahigh molecular weight synthetic polymer resistant to hydrolysis. Thecarbon-carbon backbone is more resistant to hydrolysis. In someembodiments, the gelling agent is comprised of a copolymer derived fromacrylamide, 2-Acrylamido-2-methylpropane sulfonic acid (AMPS), and vinylphosphonate. Even with the carbon-carbon backbone, the fracturing fluidsystem requires more additives in order to remain functional as afracturing fluid system in high temperature conditions. A cross linkingagent can be added to increase viscosity of the fracturing fluid system.The method of the invention includes cross linking the gelling agent,such as cross linking the gelling agent with metal ions of a crosslinking agent. For a gelling agent comprised of a high molecular weightsynthetic polymer, a cross linking agent can be selected from zirconiumbased compounds and titanium based compounds.

An inverting surfactant can be added to hydrate the emulsion polymer inthe water, when the gelling agent is comprised of an emulsion polymer.Another fluid component can be a breaker. At relatively lowtemperatures, a breaker has been used to oxidize a fracturing fluidsystem so that the fluid components can be more easily recovered fromthe fractures. After the proppant is delivered, the step of recoveringrequires the fracturing fluid system to be removed from the rockformation. In the present invention at high temperatures, a breaker,such as sodium bromated, can be used to break the fracturing fluidsystem in a controlled manner. The timing and depth of loading thebreaker can be controlled. Oxidizing breakers, such as sodium bromatedand peroxides can be used, and the breakers may also be encapsulated foradditional control of the release of the breaker into the fracturingfluid system. Another fluid component can be sodium thiosulfate, as asecond stabilizer in the fracturing fluid system. The temperature of therock formation and the duration of exposure to the high temperaturedetermine the amount of water, the gelling agent, such as a highmolecular weight synthetic copolymer, stabilizer of ascorbic acid, andother fluid components and additives. Furthermore, the well conditionsand the type of treatment can affect particular amounts.

Embodiments of the present invention include injecting a fracturingfluid system with the ascorbic acid as a stabilizer. The presentinvention includes forming the ascorbic acid by loading an ascorbatesalt and an acid or loading ascorbic acid directly into the fracturingfluid system. As an acid, the amount of ascorbic acid adjusts the fluidsystem, such as adjusting to a pH ranging from about 3.5 to 6.9, whenthe fluid system is a linear gel before a cross linking agent is added.In other embodiments, the fracturing fluid system further comprises a pHadjusting agent as a second adjustment to the pH added to the fracturingfluid system after the stabilizer. The second pH adjusting agent canalso maintain the fracturing fluid system in a range of about 3.5 to 6.9as a linear gel, before cross linking. In particular, the range can be4.5 to 6.0 with the second pH adjusting agent. Other additives, such asthe cross-linking agent, will affect the pH such that the pH adjustingagent may be needed in addition to the ascorbic acid already added as astabilizer.

The ascorbic acid of the fracturing fluid system also delays crosslinking of the gelling agent. When added to the fracturing fluid systemwith a cross linking agent, the start of the cross-linking is delayed,and the gelling agent increases in apparent viscosity without a spike.The apparent viscosity is stabilized within a temperature range of150-260 degrees Celsius. The method of the present invention includesadding a cross linking agent to the fracturing fluid system and crosslinking the gelling agent from a linear gel at a pre-set depth in thewellbore, after the step of delaying cross linking with ascorbic acid.Furthermore, the method includes adjusting the amount ascorbic acid inthe fracturing fluid system so as to control the amount of delay. Theamount of time delaying cross linking can be regulated by the presentinvention. The apparent viscosity can be increased at the target lowerdepth in the wellbore, not so early, when the fracturing fluid system isstill being pumped to the target lower depth. High shear from pumpingwould degrade the fracturing fluid system too much before reaching thenew deeper wells. The embodiments of the present invention includeinjecting a fracturing fluid system with ascorbic acid ranging from 1-50ppt and 3-25 ppt so as to adjust pH and delay the cross linking agent.

Example 1

FIGS. 1 and 2 show embodiments of the present invention at 180 degreesCelsius. FIG. 1 shows rheological properties over 2 hours afterinjecting, and FIG. 2 shows rheological properties over an isolated 15minutes after injecting.

Test samples include fracturing fluid systems comprised of UltraGel HT™,which is a copolymer of acrylamide, 2-Acrylamido-2-methylpropanesulfonic acid (AMPS), and vinyl phosphonate, as the gelling agent, aninverting surfactant, ascorbic acid as the stabilizer, and azirconium-based cross linking agent (XL1). An alternate test sampleincludes acetic acid as the pH adjusting agent, instead of ascorbicacid.

A first test sample has 12.5 gal/1000 gal of gelling agent, 10 lb/1000gal of ascorbic acid, and 3 gal/1000 gal of cross linking agent. Asecond test sample has 12.5 gal/1000 gal of gelling agent, 7.5 lb/1000gal of ascorbic acid, and 3 gal/1000 gal of cross linking agent. A thirdtest sample has 12.5 gal/1000 gal of gelling agent, 5 lb/1000 gal ofascorbic acid, and 3 gal/1000 gal of cross linking agent. The alternatetest sample has 12.5 gal/1000 gal of gelling agent, 5 lb/1000 gal ofacetic acid, and 3 gal/1000 gal of cross linking agent. The temperatureof the test samples are superimposed in FIGS. 1 and 2 to show the hightemperature conditions.

FIGS. 1 and 2 contrast the alternative test sample and the first,second, and third test samples. The apparent viscosity of the prior artacetic acid as a pH adjusting agent spikes. By replacing acetic acidwith ascorbic acid, the apparent viscosity of the fracturing fluidsystem is more leveled. There is no spike at the beginning, and theapparent viscosity maintains much higher values over 2 hrs, even at theelevated temperature. Furthermore, the start of cross linking is furtherdelayed. With ascorbic acid, the cross linking persists longer under theelevated temperature conditions. FIGS. 1 and 2 also show injecting afracturing fluid system without an additional pH adjusting agent. Theascorbic acid was sufficient as a pH adjusting agent in the first andsecond test samples. Therefore, ascorbic acid functions as an acidicadjusting agent, a gel stabilizer and a cross linking control agent.Much more simplified fluid systems with greatly improved hightemperature rheological performance were obtained using the method ofthe present invention.

Example 2

FIGS. 3 and 4 show embodiments of the present invention at 200 degreesCelsius. FIG. 3 shows rheological properties over 2 hours afterinjecting, and FIG. 4 shows rheological properties over an isolated 15minutes after injecting. Example 2 shows the durability of the inventionin the range of higher temperatures as 200 degrees Celsius.

Test samples include fracturing fluid systems comprised of UltraGel HT™,which is a copolymer of acrylamide, AMPS, and vinyl phosphonate, as thegelling agent, an inverting surfactant, ascorbic acid as the stabilizer,and a zirconium-based cross linking agent (XL1). An alternate testsample includes sodium thiosulfate as the stabilizer and acetic acid asthe pH adjusting agent, instead of ascorbic acid.

A first test sample has 17.5 gal/1000 gal of gelling agent, 10 lb/1000gal of ascorbic acid, and 3.5 gal/1000 gal of cross linking agent. Asecond test sample has 15 gal/1000 gal of gelling agent, 10 lb/1000 galof ascorbic acid, and 3.5 gal/1000 gal of cross linking agent. A thirdtest sample has 15 gal/1000 gal of gelling agent, 10 lb/1000 gal ofascorbic acid, and 3 gal/1000 gal of cross linking agent. A fourth testsample has 15 gal/1000 gal of gelling agent, 7.5 lb/1000 gal of ascorbicacid, and 3 gal/1000 gal of cross linking agent. The alternate testsample has 17.5 gal/1000 gal of gelling agent, 10 lb/1000 gal of sodiumthiosulfate, 5 gal/1000 gal of acetic acid, and 3.5 gal/1000 gal ofcross linking agent. The temperature of the test samples aresuperimposed in FIGS. 3 and 4 to show the high temperature conditions at200 degrees Celsius.

FIGS. 3 and 4 contrast the alternative test sample and the first testsample. The prior art sodium thiosulfate as stabilizer and acetic acidas a pH adjusting agent spikes. By replacing the sodium thiosulfate andacetic acid with ascorbic acid, the apparent viscosity of the fracturingfluid system remained more leveled. The damping continues at 200 degreesCelsius, and the apparent viscosity maintains much higher values over 2hrs. Furthermore, four test samples show the delayed cross linking bythe ascorbic acid of the present invention. FIG. 4 shows the delayedstart time for the cross linking by the ascorbic acid. With ascorbicacid, the cross-linking continues to persist longer under the elevatedtemperature conditions. FIGS. 3 and 4 further support injecting afracturing fluid system without an additional pH adjusting agent. Theascorbic acid was sufficient as a pH adjusting agent in the firstthrough fourth test samples. Under an additional high temperaturecondition, ascorbic acid functions as an acidic adjusting agent, a gelstabilizer and a cross-linking control agent.

Example 3

FIG. 5 show embodiments of the present invention at 230 degrees Celsius.FIG. 5 shows rheological properties over 1 hour after injecting. Example3 shows the embodiment at another higher temperature in the range ofhigher temperatures.

Test samples include fracturing fluid systems comprised of UltraGel HT™,which is a copolymer of acrylamide, AMPS, and vinyl phosphonate, as thegelling agent, an inverting surfactant, ascorbic acid as the stabilizer,and a zirconium-based cross linking agent (XL1).

A first test sample has 17.5 gal/1000 gal of gelling agent, 15 lb/1000gal of ascorbic acid, 3 gal/1000 gal of cross linking agent, and 3gal/1000 gal of inverting surfactant. A second test sample has 17.5gal/1000 gal of gelling agent, 20 lb/1000 gal of ascorbic acid, 3gal/1000 gal of cross linking agent, and 3 gal/1000 gal of invertingsurfactant. The temperature of the test samples are superimposed in FIG.5 to show the high temperature conditions at 230 degrees Celsius.

FIG. 5 also shows the delayed cross linking by the ascorbic acid of thepresent invention and the delayed start time for the cross linking bythe ascorbic acid, similar to the Examples at 180 degrees Celsius and200 degrees Celsius. With ascorbic acid, the cross-linking continues topersist longer under still another elevated temperature condition. Thedamping continues at 230 degrees Celsius, and the apparent viscositymaintains much higher values over 2 hrs.

Example 4

FIG. 6 show embodiments of the present invention at 200 degrees Celsius.FIG. 6 shows rheological properties over 2 hours after injecting.Example 4 shows the embodiment with shear history simulation in therange of higher temperatures.

Test samples include fracturing fluid systems comprised of UltraGel HT™,which is a copolymer of acrylamide, AMPS, and vinyl phosphonate, as thegelling agent, ascorbic acid as the stabilizer, a zirconium-based crosslinking agent (XL1), and an inverting surfactant with a shear historysimulation at 1350 s⁻¹, indicated as “SHS 1350 s-1”.

A first test sample has 20 gal/1000 gal of gelling agent, 11 lb/1000 galof ascorbic acid, 3 gal/1000 gal of cross linking agent, and 3 gal/1000gal of inverting surfactant. The temperature of the test sample issuperimposed in FIG. 6 to show the high temperature conditions at 200degrees Celsius.

FIG. 6 shows the high shear stability of the fracturing fluid system forthe method of the present invention. When used in the field, afracturing fluid system experiences a much higher shear before enteringfractures than the shear in a lab rotation viscometer. The high shearcan have a detrimental effect on the downhole performance of the fluid.FIG. 6 shows a simulation of a fracturing fluid system closer to actualfield conditions, wherein the rheological properties are suitable forfracturing. FIG. 6 shows that injecting a fracturing fluid system inconditions at high sheer is possible with the method of the presentinvention.

Example 5

FIG. 7 show embodiments of the present invention at 180 degrees Celsius.FIG. 7 shows rheological properties over 2 hours after injecting.Example 5 shows the embodiment with breaker in the range of highertemperatures.

Test samples include fracturing fluid systems comprised of UltraGel HT™,which is a copolymer of acrylamide, AMPS, and vinyl phosphonate, as thegelling agent, an inverting surfactant, ascorbic acid as the stabilizer,a zirconium-based cross linking agent (XL1), and a breaker of sodiumbromated (NaBrO3).

A first test sample has 15 gal/1000 gal of gelling agent, 10 lb/1000 galof ascorbic acid, 2 gal/1000 gal of cross linking agent, 3 gal/1000 galof inverting surfactant, and 0.37 ppt NaBrO3. A second test sample has15 gal/1000 gal of gelling agent, 10 lb/1000 gal of ascorbic acid, 2gal/1000 gal of cross linking agent, 3 gal/1000 gal of invertingsurfactant, and 1 ppt NaBrO3. A third test sample has 15 gal/1000 gal ofgelling agent, 10 lb/1000 gal of ascorbic acid, 2 gal/1000 gal of crosslinking agent, 3 gal/1000 gal of inverting surfactant, and 1.5 pptNaBrO3.

The temperature of the test sample is superimposed in FIG. 7 to show thehigh temperature conditions at 180 degrees Celsius.

FIG. 7 shows the fracturing fluid systems holding the stability of theapparent viscosity with the breaker. The ascorbic acid continues todelay the cross linking, and any spike in viscosity remains reduced.FIG. 7 shows functionality of the fluid system in the higher temperatureof the present invention with a breaker. In the field, a breaker canstill be used at the high temperature range in a controlled manner torecover fluid components, after the step of fracturing.

The present invention provides a method for well stimulation byhydraulic fracturing a rock formation through a wellbore under hightemperature conditions. Conventional fracturing fluid systems break downand require multiple additives to maintain functionality as a fracturingfluid system. The present invention is a method for hydraulic fracturinga rock formation in a high temperature range, such as 150-260 degreesCelsius. The method includes a fracturing fluid system that remainsstable without breaking down. The viscosity of the gel based fracturingfluid system withstands high shear during pumping and the elevatedtemperatures of downhole conditions. In addition to a high molecularweight synthetic polymer as the gelling agent, the fracturing fluidsystem includes ascorbic acid as a stabilizer and pH adjusting agent.The gel is stabilized without spikes in apparent viscosity, and there isdelayed cross linking. Depending on the wellbore conditions, delayedcross linking of fracturing fluid systems is important, especially fordeep wells. With deep wells, the time for the fracturing fluid systemsto reach the bottom of the wellbore and the fractures can be very long,and the fracturing fluid systems need to be cross linked to gainsignificant viscosity to carry proppant into the fractures at this deeplocation. Without a delay in cross linking, the fracturing fluid systemswould be damaged mechanically when pumped downhole at high rates,especially for metal-ion cross-linked fracturing fluid systems.Therefore, controlled delay of the cross linking is a critical advantageof the fracturing fluid systems of the present invention. The presentinvention supports that the addition of ascorbic acid providescontrolled delay of the cross linking and that the delay time isadjusted by loading of the ascorbic acid. The apparent viscosity avoidsspikes with the addition of the stabilizer of the present invention andcontinues to maintain functionality with apparent viscosity afterinjecting.

Embodiments of the present invention show that ascorbic acid as astabilizer is compatible with other fluid components, such as crosslinking agents, inverting surfactants used with emulsion polymers as thegelling agent, and breakers. In the field, the method of the presentinvention is compatible with the fluid components for addressingdifferent fracturing conditions in the formation. The performance of thefracturing fluid system with ascorbic acid is confirmed by the testresults and data.

In the present invention, the amount of ascorbic acid can keep thefracturing fluid system at a pH ranging from about 3.5 to 6.9, such asthe fracturing fluid system being a linear gel before adding the crosslinking agent. An additional pH adjusting agent is not always requiredin the fracturing fluid system. In other embodiments, there can be aneed for a pH adjusting agent as a second adjustment to the pH added tothe fracturing fluid system after the stabilizer of the presentinvention. Other additives, such as the cross linking agent, will affectthe pH such that the pH adjusting agent may be needed in addition to theascorbic acid as stabilizer. When the pH is not within the range of 3.5to 6.9, an additional pH adjusting agent can be added. Unlike the priorart, this secondary pH adjusting agent is adjusted according to theamount of stabilizer, the ascorbic acid, and the other additives. OtherpH adjusting agents are not added at the rate and conditions of thefluid system of the present invention.

The present invention further provides injecting a fracturing fluidsystem that is biologically friendly and carries less risk ofenvironmental contamination. Ascorbic acid is a naturally occurringcompound, which has not been used in the method of the presentinvention. The problems of other stabilizers, like phenothiazine andsodium thiosulfate are avoided without compromising the functionality ofthe fracturing fluid. The solubility of the ascorbic acid as stabilizerdoes not require a special solvent with risk to the environment.

In the present invention, it is possible for a copolymer of acrylamide,AMPS, and vinyl phosphonate to function as a gelling agent beyond theconventional polysaccharides, like guar gum. Beyond the knownapplications with a high molecular weight copolymer, the presentinvention includes injecting with ascorbic acid as a gel thermalstabilizer, a pH adjusting agent, and a cross linking delay agent. Theknown gel thermal stabilizers, such as sodium thiosulfate, are generallyoxygen scavengers for the conventional fracturing fluid systems. In hightemperature conditions, ascorbic acid has not been disclosed as anadditive for these specialized fracturing fluid systems. The presentinvention includes a method of fracturing with ascorbic acid in a newfracturing fluid system for conditions previously unrealized with thelevel of drilling technology.

The foregoing disclosure and description of the invention isillustrative and explanatory thereof. Various changes in the details ofthe illustrated structures, construction and method can be made withoutdeparting from the true spirit of the invention.

1. A method for well-stimulation through a wellbore in a rock formation,comprising the steps of: injecting a fracturing fluid system to saidrock formation, said fracturing fluid system comprising: a proppant; anda plurality of fluid components, said fluid components being comprisedof: water; a gelling agent; and a stabilizer comprising ascorbic acid;fracturing said rock formation at a temperature between 150-260 degreesCelsius; increasing apparent viscosity without a spike in apparentviscosity with said ascorbic acid; and recovering said fluid componentsof said fracturing fluid system from said wellbore.
 2. The method forwell-stimulation, according to claim 1, wherein said proppant iscomprised of a granular material to prevent fractures from closing. 3.The method for well-stimulation, according to claim 1, wherein saidgelling agent is comprised of a high molecular weight synthetic polymerresistant to hydrolysis.
 4. The method for well-stimulation, accordingto claim 1, wherein said gelling agent is comprised of a copolymerderived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinylphosphonate.
 5. The method for well-stimulation, according to claim 1,wherein said fracturing fluid system further comprises a cross linkingagent, the method further comprising the step of: cross linking saidgelling agent with said cross linking agent so as to increase viscosityof said fracturing fluid system.
 6. The method for well-stimulation,according to claim 5, wherein said gelling agent is comprised of a highmolecular weight synthetic polymer, and wherein the step of crosslinking said gelling agent comprises the step of: cross linking thepolymer with metal ions with said cross linking agent so as to increaseviscosity of said fracturing fluid system.
 7. The method forwell-stimulation, according to claim 5, wherein said cross linking agentis selected from at least one of a group consisting of boron basedcompounds, zirconium based compounds, and titanium based compounds. 8.The method for well-stimulation, according to claim 3, wherein saidfracturing fluid system further comprises an inverting surfactant tohydrate the polymer in said water, the polymer being an emulsionpolymer.
 9. The method for well-stimulation, according to claim 1,wherein said fracturing fluid system further comprises a breaker, andwherein the step of recovering said fluid components comprises loadingsaid breaker into said fracturing fluid system, after the step offracturing.
 10. The method for well-stimulation, according to claim 1,wherein the step of injecting said fracturing fluid system comprises:forming said ascorbic acid in said fracturing fluid system by loading anascorbate salt and an acid into said fracturing fluid system.
 11. Themethod for well-stimulation, according to claim 1, wherein saidfracturing fluid system further comprises a cross linking agent, themethod further comprising the steps of: adjusting pH of said fracturingfluid system with said ascorbic acid, said fracturing fluid systemhaving a pH ranging from about 3.5 to 6.9 as a linear gel before addingsaid cross linking agent to said fracturing fluid system.
 12. The methodfor well-stimulation, according to claim 1, wherein said fracturingfluid system further comprises a cross linking agent, the method furthercomprising the step of: delaying cross linking of said gelling agentwith said ascorbic acid.
 13. (canceled)
 14. The method forwell-stimulation, according to claim 12, further comprising the stepsof: adding said cross linking agent to said fracturing fluid system; andcross linking said gelling agent at a pre-set depth, after the step ofdelaying cross linking with said ascorbic acid.
 15. The method forwell-stimulation, according to claim 12, wherein the step of delayingcross linking comprises: delaying cross linking for an amount of time,the method further comprising the steps of: adjusting an amount ofascorbic acid in said fracturing fluid system so as to control saidamount of time.
 16. The method for well-stimulation, according to claim1, wherein said ascorbic acid ranges from 1-50 ppt so as to adjust pHand delay said cross linking agent.
 17. The method for well-stimulation,according to claim 1, wherein said ascorbic acid ranges from 3-25 ppt soas to adjust pH and delay said cross linking agent.
 18. The method forwell-stimulation, according to claim 1, wherein said fracturing fluidsystem further comprises a pH adjusting agent, said pH adjusting agentbeing added to said fracturing fluid system after said stabilizer. 19.The method for well-stimulation, according to claim 18, wherein said pHadjusting agent maintains said fracturing fluid system in a range ofabout 3.5 to about 6.9 as a linear gel.
 20. The method forwell-stimulation, according to claim 18, wherein said pH adjusting agentmaintains said fracturing fluid system in a range of about 4.5 to about6.0.